FIELD OF THE INVENTION

The present invention relates to a drill bit for use in reverse drilling apparatus and/or a reverse circulation drilling apparatus utilising such a drill bit. Such a drill bit could be used in various formation environments (i.e., is all terrain) including competent, incompetent or flooded.

BACKGROUND

Reverse circulating (RC) drilling is used within the mineral exploration sector. The objective is to drill rapidly through a formation(s) to sample for various valuable minerals. Such formations, while RC drilling is commenced, may see various changes in the formation terrain encountered. This includes competent, incompetent or even flooded terrain. In general terms, a competent formation means that when drilled the formation generally does not need support to remain open, an incompetent formation generally requires support to prevent the opening collapsing and flooded generally refers to the formation containing water or other fluid.

There are two main types of RC drilling.

One is, air (pneumatic) reverse circulation drilling. This is the most common method; whereby large air compressors pump large volumes of compressed air down the outer cavity of dual walled drill rods. The compressed air: a) energises an air hammer for rapid penetration of a hard formation to chip rocks, and b) pushes the rock chips (generated by the hammer striking a drill bit and crushing the rock) to surface through the centre cavity in the dual walled drill rods for analysis by geologists at surface.

While effective in dry competent formations, pneumatic hammers struggle as they encounter groundwater or a flooded environment (a common occurrence) to the point that they cease to operate. In addition, even in dry competent formations the volume of compressed air that needs to be pumped down deep holes becomes impractical. Thus very large compressors are required that are extremely expensive to operate, as well as being potentially dangerous. As the depth of the borehole increases, the energy and pressure required to operate pneumatic hammers also increases. This increase becomes impractical, more expensive and dangerous at large depths due to the larger compressors posing significant safety concerns to operators such that the increased expense and safety concerns outweighs the benefits.

Alternatively, a relatively new technology is being increasingly used - fluid reverse circulation hammer drilling. Fluid is used instead of air to energise fluid hammers and return rock chips to surface for analysis. To date, commercially available fluid hammers only work with very clean water and are not able to survive with recycled drilling fluids. This makes them commercially impractical, except for niche applications where a ready supply of clean water is available, i.e., modifying water with drilling mud for bore control is not required.

The applicant's hybrid drill bit as described in W02018/116140 can be used with readily available drilling fluid. It can also be used in combination with the fluid driven hammer/oscillation apparatus. For example, it can be used with fluid driven hammer/oscillation tools that can reliably work with recycled drilling fluids (dirty fluids) in flooded environments, and these are provided by the present applicant. Such fluid tools comprise: the magnetic hammer as described in W02009/028964, the radial hammer described in W02012/002827, and the vibratory apparatus described in WO2015/193799 or WO2012/161595. All these are incorporated herein by reference in their entirety. While these types of fluid tools can be used, they have lower impact energy (compared to pneumatic hammers) than conventional pneumatic hammers.

SUMMARY OF INVENTION

It is an object of the present invention to provide a drill bit for use in reverse circulation (RC) drilling. Preferably the drill bit can be used in RC drilling apparatus that use drilling fluid. Preferably, the drill bit can be used in RC drilling operations in competent and incompetent formations. Preferably, the RC drilling apparatus can work in combination with fluid driven hammer/oscillation apparatus

The present inventor has devised a drill bit that can be used in RC drilling using drilling fluid. Embodiments can work in competent, incompetent and flooded formations and operate with lower energy drilling fluid driven hammer/oscillation apparatus.

Preferably, the drill bit can work in conjunction with fluid driven hammer/oscillation tools (such as those referenced above) with modest energy output and that can work in flooded environments, that are either competent and/or incompetent formations, provide strong drilling performance, and good bit life. In one aspect the present invention may be said to comprise a drill bit for coupling in use to an RC drilling apparatus, the drill bit comprising: an annular drill bit that is rotatable to cut a formation bore face, a concentric drill bit, wherein: the annular drill bit comprises a body and an annular cutting element with a continuous bit face configured such that in use, when the bit face seats on the bore face, drilling fluid that flows through the annular drill bit is retarded from leaking from the annular drill bit through the bit face/bore face interface.

Optionally the annular cutting element comprises one or more internal apertures for expelling drilling fluid from inside the drill bit to the bore face.

Optionally each internal aperture forms the exit of a respective fluid channel in the body of the annular drill bit.

Optionally the annular cutting element comprises one or more internal recesses on the inner perimeter and each internal aperture is disposed in a respective internal recess.

Optionally the drilling fluid expelled to the bore face lubricates the cutting element to assist drilling and/or clears and/or carries cuttings away from the bore face.

Optionally the drill bit further comprises one or more fluid channels in the concentric drill bit for passage of fluid carrying cuttings.

Optionally the cutting element comprises one or more external apertures for expelling drilling fluid from inside the drill bit to outside the drill bit.

Optionally drilling fluid expelled to outside the drill bit lubricates the drill bit in a bore.

Optionally each external aperture forms the exit of a respective fluid channel in the body of the annular drill bit.

Optionally the annular cutting element comprises one or more external recess on the outer perimeter and each external aperture is disposed in a respective external recess.

Optionally the concentric drill bit is axially setback from the annular drill bit to create a recess such that in use a core plug is unconfined by the surrounding formation.

Optionally the concentric drill bit is splined to or relative to the annular drill bit such that it can rotate with the annular drill bit and when energised by the RC drilling apparatus move axially relative to the annular drill bit. In another aspect the present invention may be said to comprise a RC drilling apparatus comprising a drill bit according to any one of the preceding statements

Optionally in use the RC drilling apparatus creates chip samples by breaking the core plug for return to the surface through the fluid channels in the concentric drill bit.

Optionally in use when the concentric drill bit rotates with the annular drill bit it contacts the unconfined core plug in the recess to break the core plug.

Optionally in use when the RC drilling apparatus is energised, in addition to the rotation of the concentric drill bit, the concentric drill bit moves axially and contacts the unconfined core plug in the recess to assist with the breaking of the core plug.

Optionally in use: the annular coring drill bit is or can be coupled to and rotated by a rotational drive of a drilling apparatus, and the concentric drill bit is or can be coupled to a repeatable force generating apparatus that on activation can repeatedly axially move the concentric drill bit.

Optionally in use drilling fluid passes through the internal apertures in the cutting element to clear cuttings and/or lubricate the cutting element, and the cuttings laden fluid returns to the surface through the fluid channels in the concentric drill bit.

Optionally in use drilling fluid passes through the external apertures in the cutting element to lubricate the drill bit in the bore.

Optionally the cutting element is a diamond impregnated matrix.

Optionally the concentric drill bit has bit inserts for breaking the core plug.

Optionally the bit inserts are ballistic bits or PDC bits.

Optionally the bit inserts are tapered to increase point loading and promote core plug breaking, and preferably are at right angles to the concentric drill bit face.

Optionally the concentric drill bit is splined to or relative to the annular drill bit such that it can move axially relative to the annular drill bit but can rotate with the annular drill bit.

Optionally the concentric drill bit rotates but does not oscillate. Also described is a drill bit or RC drilling apparatus works with a repeatable force generating apparatus as an impact apparatus or an oscillation apparatus configured to repeatedly axially move the concentric drill bit by impact or oscillation (such as a vibration).

Optionally: a. the impact apparatus is a hammer, such as a magnetic hammer, pneumatic hammer, fluid hammer or any suitable hammer means to provide impact force to the concentric bit to break the core plug, or b. the oscillation apparatus provides oscillatory force (such as a vibration force) to the concentric bit to break the core plug.

Also described is a drilling apparatus with a drill bit according to any preceding statement and configured to rotate the annular coring bit and repeatedly axially move the concentric drill bit.

Optionally the drilling apparatus comprises: a drillstring casing coupled to and operable to rotate the annular coring bit, and a repeatable force generating apparatus coupled to and operable to repeatedly axially move the concentric drill bit.

Optionally the repeatable force generating apparatus is splined to the drillstring casing.

Optionally the repeatable force generating apparatus provides a vibration to the annular coring bit sufficient to enhance the performance of the coring bit.

Also described is a drill bit according to any statement above or a drilling apparatus according to any statement above wherein the recess height, the number of bit inserts on the concentric drill bit and the force applied to the drill bit can be configured to generate a desired size of chip sample when breaking the core plug.

Also described is a drill bit or drilling apparatus according to any preceding statement wherein breaking the core plug produces fractures in the formation to assist drilling.

It is intended that reference to a range of numbers disclosed herein (for example, 1 to 10) also incorporates reference to all rational numbers within that range (for example, 1, 1.1, 2, 3, 3.9, 4, 5, 6, 6.5, 7, 8, 9 and 10) and also any range of rational numbers within that range (for example, 2 to 8, 1.5 to 5.5 and 3.1 to 4.7). The term "comprising" as used in this specification means "consisting at least in part of". Related terms such as "comprise" and "comprised" are to be interpreted in the same manner.

This invention may also be said broadly to consist in the parts, elements and features referred to or indicated in the specification of the application, individually or collectively, and any or all combinations of any two or more of said parts, elements or features, and where specific integers are mentioned herein which have known equivalents in the art to which this invention relates, such known equivalents are deemed to be incorporated herein as if individually set forth.

DETAILED DESCRIPTION OF DRAWINGS

Embodiments will now be described with reference to the following drawings, of which:

Figures 1A, IB show in diagrammatic form a general embodiment in elevation cross- sectional view in an oblique plane of a drill bit to use with a reverse circulation drilling apparatus showing bit inserts and a reverse fluid channel.

Figure 1C shows in diagrammatic form an exploded perspective view of the drill bit.

Figure 2 shows a perspective view of the drill bit coupled to a drillstring casing

Figure 3A shows in diagrammatic form a reverse circulation drilling apparatus comprising the drill bit according to the first and second variations.

Figure 3B, 3C shows in diagrammatic form the bottom of the reverse circulation drilling apparatus comprising the drill bit according to the third variation, showing the internal and external recesses and corresponding fluid flow respectively.

Figures 4 and 5 show variations of the hybrid drill bit with a cutting element according to a first variation.

Figure 6 shows how the cutting element of the Figures 4 and 5 seats against the bore face.

Figure 7 shows a hybrid drill bit with a cutting element according to a second variation.

Figure 8 shows a hybrid drill bit in a partial cutaway view to show the internals of a cutting element according to a third variation including internal and external recesses with openings for fluid.

Figure 9A, 9B, 9C show partial cross-sections of Figure 8 shown the galleries. Figure 10 shows an end view of Figure 11, and

Figure 11 shows the hybrid drill bit of Figure 8 without the concentric drill bit.

DETAILED DESCRIPTION OF EMBODIMENT

A drill bit as described in WO2018/116140 (which is in incorporated herein by reference in its entirety), can be used for RC drilling. During RC drilling the drill bit 10 can encounter "incompetent" rock - this is rock with fractures or at least when drilled may require support to remain open. Traditionally, RC drilling with prior art drill bits can encounter problems with incompetent rock and/or formations that include incompetent rock or fracture zones. The drilling fluid that passes down the drill string to lubricate the cutting element (annular drill bit) and for carrying cuttings back uphole can escape into the fractures of the rock. This reduces flow, volume and/or pressure of the drilling fluid that goes back uphole, thus reducing efficiency of carrying cuttings.

Field testing has shown that when drilling in fractured formations:

• the drilling fluid flow leaks to or into the formation instead of pushing the cuttings up through the hammer bit/hammer and dual walled rods to surface for analyses; and further,

• the cuttings are not cleared from the drill bit.

As a result of this -

• The rate of production (ROP) slows dramatically and can stop completely.

• There can be excessive wear on the Inside Diameter (ID) of the annular drill bit.

• Samples may not reach the surface for analysis.

• There can be blocked ports in the hammer bit.

• There is potentially a blocked hammer as there is no fluid flow (if used).

• There might be a loss of expensive fluid to the formation.

Embodiments described herein provide a drill bit 10 (optionally termed "hybrid drill bit") that can be used in fluid RC drilling (optionally with a fluid driven hammer), wherein the drill bit is adapted so that it can operate in incompetent formations, as well as competent formations and flooded terrain/formations. The present inventors have come up with an improvement on the hybrid drill bit 10 to compensate for RC drilling in incompetent rock, as well as other formations. They have realised that it is not necessary to have a significant quantity of drilling fluid that escapes through the annular drill bit castellations (galleries) of prior art drill bits and into the area between the drill string 41 and the bore hole 7 (see e.g. Figure 3A). The present inventors have devised a hybrid drill bit 10 that retards (that is, prevents or at least reduces) the volume of drilling fluid that escapes from the drill bit into the external area between the outer perimeter of the drill string 41 and the bore hole 7. In doing so, more drilling fluid is retained within the drill bit 10, thus preserving pressure, flow and volume for carrying cuttings up to the surface, even where some of the drilling fluid is lost into the fractures.

Figures 1A, IB in general form an embodiment of a drill bit (optionally termed "hybrid drill bit") in diagrammatic form. It is for incorporation in/coupling to a reverse circulation (RC) drilling apparatus (such as shown in Figure 3A, 3B, 3C) for use in RC drilling field applications with fluid driven hammers. The (hybrid) drill bit 10 comprises an annular drill bit (outer component) 11 and an inner concentric drill bit (inner component) 12. The hybrid bit can be used with vibratory/impact devices (to be described below), such devices may have modest energy output, and preferably operate with recycled modified and dirty fluids.

The hybrid drill bit 10 concentric drill bit (inner component) 12 resides concentrically (coaxially) inside an interior portion 33 of the annular drill bit 11. An example of a concentric drill bit 12 is shown in more detail in the exploded form of the hybrid drill bit in Figure 1C. The concentric drill bit 12 (which could also be termed "coaxial drill bit") can be splined to the interior wall surface of the annular drill bit 11 such that it rotates with the annular drill bit, but can move axially relative to it. In another option, the concentric drill bit is not splined to the annular drill bit 11, such that the concentric drill bit can still move axially relative to the annular drill bit, but the annular drill bit can also rotate relative to the concentric drill bit 12. The concentric drill bit is seated on the inner wall of the annular bit 11 such that the concentric drill bit is axially set back a distance "X" from the face 15 of the annular drill bit 11. This creates a recess 13 between the annular bit interior 33 and the face 16 of the concentric drill bit 12. As the annular drill bit 11 rotates and drills into the formation, the core sample 6 is formed in the recess 13 to create a core plug (also termed "knub") 6 (see Figure IB). Thus, the annular drill bit 11 creates an isolated core of rock 6 that is unconfined by the pressure of the surrounding rock mass 5. This unconfined core plug 6 is much easier to break. The concentric drill bit 12 has a bit face 16 provided with bit inserts 17.

The concentric bit 12 can be rotated (by the RC drilling apparatus 40 in use) either with or independently to the rotation of the annular bit 11 to assist with breaking the core plug 6. Additionally, the annular drill bit can be vibrated or otherwise perturbed to assist with drilling into the formation to create the core plug.

Optionally, the concentric drill bit 12 can be repeatedly moved axially as shown by arrow "A" in Figure IB (by an RC drilling apparatus 40 in use) relative to and within the interior of the annular drill bit 11/recess 13 and relative to the bore face 8/ core plug 6. The concentric core bit 12 can be repeatedly moved by an apparatus (see Figure 3A) that provides impacts and/or oscillations, as will be described later. The concentric drill bit face 16 repeatedly axially moves as per arrow "A" into the recess 13 so that the bit inserts 17 hit the core plug 6 created by the annular drill bit 11, and breaks (also termed "chipping") the core plug 6 into chip samples - e.g. by cutting, chipping, crushing (or the like) the core plug.

The bit inserts 17 can be any suitable inserts for breaking the core plug 6, such as ballistic bits or PDC bits. The bits can be any suitable shape to facilitate core plug breaking. Preferably, the bits are tapered to increase point loading to facilitate core plug breaking. The bit inserts 17 are preferably placed at a perpendicular angle to the rock face 8/bit face 16, and preferably not angled away from the bit face 16. Angled inserts are not needed to maintain borehole gauge, as this outcome is achieved by the annular drill bit 11. This allows the bit inserts 17 to be more aggressively shaped (such as tapered as described above) - which increases the point loading into the formation, to improve chipping performance. A suitable number of bit inserts 17 is provided to achieve the required chipping.

The concentric drill bit has return holes 18 for passage of drilling fluid 49 (such as drilling mud) laden with chip samples. In use, drilling fluid 49 from the RC drilling apparatus 40 passes down through the apparatus between the outer 42 and inner 46 drillstring casing that forms a dual casing drillstring, and exits to the bore face, and then returns through the return holes 18 carrying the chip samples to transport them back top hole for analysis. This will be explained later further with respect to Figure 3A, 3B, 3C.

The concentric drill bit and its operation are more fully described in our patent specification published as WO2018116140

Figures 1A, IB show a general embodiment of the annular drill bit, being made of a hard material able to withstand the often-extreme temperatures, often harsh, and abrasive nature downhole. This could be for example diamond, a carbide, stone material or any other similar material capable of withstanding such conditions. The annular drill bit 11 is rotatable (by a RC drilling apparatus 40 in use - see Figure 3A, 3B, 3C) to cut into a formation 5 to cut/create a core sample 6 (see Figure IB and 3A). The annular drill bit 11 is a diamond impregnated bit 30. The annular drill bit comprises a body with a cutting element formed as an annular metallic matrix 31 with synthetic diamond inserts 32 embedded throughout the matrix or a surface set matrix, and a hollow interior 33. In use, and referring to Figure 1A, the annular drill bit 11 grinds the formation/rock 5 away at the bore face 8 as the bit is rotated and pushed into the formation. Referring to Figure IB, this creates/forms the core sample 6 in the interior 33 of the annular drill bit 11.

The annular drill bit, with variations of the cutting element, will now be described in further detail.

Figures 4 and 5 show a hybrid drill bit 10, according to one variation, which comprises an annular drill bit 11 with a body and a cutting element according to a first variation and a concentric drill bit 12 in an arrangement as described previously. There are no castellations in the cutting element of the annular drill bit 11. Rather, the annular drill bit 11 has a continuous bit face 151 - that is at least some continuous portion around the entire annular bit face without any gaps extending entirely from the inside perimeter of the face to the outside perimeter of the bit face. Galleries (recesses 157) for drilling fluid run down the inside of the annular drill bit 11, between the body of the annular drill bit and the concentric drill bit 12. The galleries 157 (recesses) provided in the internal surface of the annular cutting element 152 provide channels to allow for passage of fluid to cool the annular drill bit 11, clear cuttings, and allow passage of cuttings back up through return channels 18 in the concentric drill bit 12. However, these channels 157 do not extend all the way radially through the annular cutting element 152. The galleries open into a region 160 (see fig 6) defined by the bottom of the concentric drill bit 12, the inner cylindrical wall of the annular drill bit 11 and the bore face 8. During use, (that is when the annular drill bit 11 is rotating and grinding rock in the drilling process) fluid runs down the galleries 157, into the region 160 and back uphole through the return path 18. The continuous bit face 151 seats against the bore face 8 (see Figure 6, which shows this diagrammatically) so that there is no passage for drilling fluid 49 between the inner part 152A of the cutting element 152 of the annular drill bit 11 and the outer part 152B of the cutting element 152. This is because there are no fluid passages (such as gaps) extending entirely between the inside perimeter of the bit face to the outer perimeter of the bit face - it is continuous, so that there is a continuous engagement with the bit face and the bore face. There is effectively a seal on the interface 154 between the continuous bit face 151 and the bore face 8 to retard passage of drilling fluid 49 between the interface 154. In practice, the seal might not be perfect, and there may be small amounts of drilling fluid that can escape at the bit face/bore face interface, but from a functional point of view the passage of any fluid is reduced to a point where there is no significant fluid, and or at least fluid flow is sufficiently retarded to compensate at least partially for lost fluid through the fractures in the formation to improve flow, pressure and/or volume of fluid 49 within the drill bit 10 to allow passage of cuttings. Predominantly most, if not all, of the fluid passes back up the return holes 18.

It has been found that it is still advantageous to have some fluid outside the drill bit 10 between the outer perimeter 158 of the drill bit 10 and the bore hole 8 for lubrication and/or cooling purposes. Therefore, in a variation, one or more apertures 159 are disposed in a body 153 of the drill bit 10 to allow passage of a small amount of drilling fluid 49 from the dual walled cased drillstring to the outer annular surface 158.

Figure 7 shows a hybrid drill bit 10', according to a second variation, which comprises an annular drill bit 11' with a body 153' and a cutting element 152' according to a second variation, that can be provided with a concentric drill bit 12 in an arrangement as described previously. There are no castellations in the cutting element of the annular drill bit 11'. Rather, the annular drill bit 11' has a continuous bit face 151. In this variation, the galleries 157' in the annular drill bit 11' are made even deeper radially into the annular cutting element 152' to better allow for lubrication and clearing of cuttings. However, the galleries 157' still do not extend radially all the way through the cutting element 152', such that there is still a continuous bit face 151' that seats/interfaces 154 at/against the bore face 8 during operation to retard escape of drilling fluid 49 to the outer part 158 of the drill bit 10', as shown in Figure 6. Optionally, this embodiment shown in Figure 7 can be provided with one or more apertures 159 in the manner as described above.

The drill bit variation 10, 10' can be coupled to a RC drill string as shown in Figure 3A.

Figures 1C, 2, 8, 9A-9C, 10, 11 show a hybrid drill bit 10", according to a third variation, which comprises an annular drill bit 11" with a body 153" and a cutting element 152" according to a third variation and a concentric drill bit 12 in an arrangement as described previously. There are no castellations in the cutting element of the annular drill bit 11". Rather, the annular drill bit 11" has a continuous bit face 151". The concentric drill bit 12 is as described before and has cutting elements 17 as described previously and channels 18 for return of drilling fluid 49 laden with cuttings. The concentric drill bit 12 can be stepped back from the base of the annular drill bit 11" (as previously described), and during operation can be rotated and/or oscillated. Any part of the description used previously in relation to the concentric drill bit 12 can apply to this embodiment.

The annular drill bit 11" has a variation to the cutting element 152". The annular cutting element 152" has internal recesses 170, which are openings in the element face 151" that extend from the inner perimeter 156" radially outwards, partially (but not completely) towards the outer perimeter 158" of the annular element 152". In each internal recess 170, there is an internal aperture 172 that forms the opening of a channel (Gallery) 173 that extends from the annular cutting element 152" through the body 153" of the annular drill bit 11". The channel 173 opens to an angled portion 14 of the concentric drill bit 12 to create a cavity 13 into which the fluid can pool and feed the internal channels 173. This can be seen also in Figure 9A. The internal aperture 172 opens into an internal cylindrical region 160" of the annular drill bit 11" bounded by the concentric drill bit 12, the inner cylindrical surface 156" of the annular drill bit 11" and the bore face 8. Drilling fluid in the drillstring comes through the channel 173 through the aperture 172 into the internal region 160". This arrangement allows for passage of drilling fluid 49 during operation to lubricate and cool the cutting element 152", clear cuttings and allow passage of the fluid 49 with the cuttings up through the return channels 18 in the concentric drill bit 12. Ridges on the annular cutting element 152", such as shown in the variation of Figure 7 could also be provided.

Referring to Figures 9B and 9C, the annular cutting element also has external recesses 175, which are openings in the element face 151" that extend from the outer perimeter 158" radially inwards, partially (but not completely) towards the inner perimeter 156" of the annular element 152". In each external recess 175, there is an external aperture

176 that forms the opening of a channel (Gallery) 177 that extends from the annular cutting element 152" through the body 153" of the annular drill bit 11". The channel

177 opens to an angled portion of the concentric drill bit and cavity. This external aperture 176 opens to the bore 7 and bore face 8. Thus drilling fluid from the drillstring comes into the cavity and then through the channel 177 through the aperture 176 to exit via the external recess 175 into the bore 7 and to the bore face 8. This allows for passage of drilling fluid 49 during operation to lubricate the outer perimeter 158" and/or the cutting element 152" of the drill bit 11" against the bore hole 7. The flow rate of the fluid through the channels 177 can be moderated by closing or opening the channels 177 that feeds the external apertures 176. This can be achieved by a grub screw or the like for example. The external 175 and internal 170 recesses could have a shape similar to that of the second variation in Figure 7.

Despite the external 175 and internal recesses 170, the annular cutting element 152" has a continuous bit face 151" as shown, and that there are no openings 170, 175 that extend completely radially between the inner part 156" of the annular element 152" and the outer part 158" of the annular element 152" that provide passage of fluid when the bit face 151" seats against the rock formation/face 8 during use.

The drill bit 10" can be attached to a drill string, as shown in Figure 2 and Figure 3B, 3C.

The hybrid drill bit 10, 10', 10" and any of its variations can be used for RC drilling, such as in the arrangement shown in Figure 3A, 3B, 3C.

Figure 3A shows the hybrid drill bit variations 10 or 10' incorporated into/coupled into a RC drilling apparatus 40, such that when reference is made to 10 - this could equally mean 10'. Figure 3B, 3C shows hybrid drill bit variation 10" incorporated into/coupled into the RC drilling apparatus 40. In all cases, the drilling apparatus 40 comprises a drillstring 41. The drillstring comprises an outer rotatable drillstring casing 42 (comprised of drill rods coupled together) with a hollow interior. A drill rig 43 with a top drive/rotational drive is coupled top hole to the outer drillstring casing 42 to rotate the drillstring outer casing in use, such that the outer drillstring casing becomes a rotational drive. The hybrid drill bit 10 is coupled/incorporated into the drillstring outer casing 42. The annular drill bit component 11 is coupled to or embedded in the end of the outer drillstring casing 42. Preferably, the annular coring drill 11 bit is screwed into the end of the drillstring outer casing 42, such that the annular drill bit rotates at the same speed as the outer casing 42/drill rig 43 at surface. The concentric drill bit component 12 is seated in an axially setback manner on the inside of the annular coring drill bit 11, as previously described. Optionally, it is also coupled to the annular coring drill bit. For example, in one option the concentric drill bit 12 is splined to the interior wall surface of the annular drill bit 11 such that it rotates with the annular drill bit, but can move axially relative to it. In another option, the concentric drill bit 12 is not splined to the annular drill bit 11, such that the concentric drill bit can move axially relative to the annular drill bit whilst the annular drill bit rotates relative to the concentric drill bit 12.

An inner drillstring casing 46 (comprised of drill rods coupled together) extends inside the outer drillstring casing 42 to the uphole side/back of the concentric drill bit 12. The outer 42 and inner 46 drillstring casings form a dual casing drill string. The inner drillstring casing 46 has a hollow interior 51. A repeatable force generator apparatus 47 is provided within the drillstring outer casing 42 and is arranged so that in use it can provide a repeatable axial force B to the concentric drill bit 12 to repeatedly axially move the concentric drill bit 12 axially/longitudinally A (with respect to the bore hole and relative to the formation/bore face see figure 1A) to break a core plug 6. That force could be a repeatable impact/impulse force to provide a repeatable impact axial movement A, or it could be an oscillating/vibration force to provide a vibration/oscillating/reciprocating axial movement A. The force generator 47 could be: a) an impact apparatus like a hammer, such as a magnetic hammer, pneumatic hammer, fluid hammer or any suitable hammer means to provide impact/impulse force to the concentric drill bit 12 to break the core plug 6; or it could be: b) a vibration/oscillatory apparatus to provide oscillatory force to the concentric drill bit 12 to break the core plug 6.

In one example, the repeatable force generator apparatus 47 is a magnetic hammer as previously referenced. The concentric drill bit can be screwed into the end of the repeatable force generator apparatus 47, such as for example the shuttle of the magnetic hammer as previously referenced. The shuttle is then splined further up hole to the inside diameter of the drillstring outer casing 42 such that the concentric drill bit and the annular coring drill bit rotate at the same speed (in the case where the concentric drill bit is splined to the annular drill bit). In an alternative, the shuttle is not splined to the drillstring outer casing 42 and the concentric drill bit moves independently of the drillstring outer casing rotation. It will be apparent to those skilled in the art that other types of force generator apparatus could be used and configured and coupled to the drillstring and hybrid drill bit in other manners.

Examples of impact and vibration/oscillatory apparatus include those described in W02009/028964 (magnetic hammer), W02012/002827 (radial hammer) WO2015/193799 or WO2012/161595 (vibratory/oscillatory apparatus). All these are incorporated herein by reference in their entirety.

A drilling fluid path is provided in the apparatus comprising an annular drilling fluid path

48 that exists between the walls of the outer 42 and inner 46 drill casings. Drilling fluid

49 in use is pumped down through the annular drilling fluid path 48. The fluid 49 travelling downhole will flow towards the bore face 5, through the inner channels/galleries in the annular drill bit.

The hybrid drill bit that can be used for improved performance in RC drilling, particularly for soft or fractured formations (incompetent formations) including flooded formations. When conducting RC drilling using the drill bit 10, 10' and 10" as described above, drilling fluid passes down through the drill string in order to lubricate the cutting element and also for carrying cuttings back uphole, such as shown in Figure 3A, 3B, 3C

The drilling fluid 49 is retained within the annular drill bit and returns back past the broken core plug 6 carrying with it chip samples up through the return holes 18 in the concentric drill bit 12 and back up through the inner hollow path 51 (which also forms part of the drilling fluid path 48) of the inner drillstring casing 46. The chip laden fluid returns back up hole for analysis. The annular path 48, channel 50, bore 7, return holes 18 and interior 51 of the inner drill casing all form part of the drilling fluid path.

In the case of the first variation and second variation of the drill bit 10, 10', a small amount of fluid flows out the small opening 159 in the annular drill bit into the bore hole 7 and to the formation/bore face 8 to provide lubrication.

In the case of the third variation of the hybrid drill bit 10", a small amount of the fluid 49 travelling downhole will also flow towards the bore face hole, through the outer channels/galleries 177, 176, 175 in the annular drill bit to provide lubrication.

The combination of the rotation R of the annular drill bit (of any variation) and, where used, the repeated axial movement A of the concentric drill bit 12 improves chipping performance. The core plug 6 generated by the annular drill bit 11 through rotation forms an unconfined core plug 6, which is weaker and more prone to breaking. This makes it easier for the concentric drill bit 12 under repeated axial force to move, contact and break (via the bit inserts 17) the core plug 6 into chip samples.

In addition, optionally there could be a vibration apparatus or other apparatus to perturb the annular coring drill bit 11. Optionally, the force output from the repeatable force generation apparatus 47 could be indirectly communicated to the annular coring drill bit 11 to provide a perturbation. For example, in the case of a diamond impregnated annular drill bit, such indirect vibration that the diamond impregnated bit does experience is enough to significantly speed up the annular drill bit progress into the formation, but not sufficient to prematurely damage the annular drill bit.

In addition, optionally the concentric drill bit 12 could be rotated to expedite breaking of the core plug, e.g. through being splined to the drillstring outer casing 42 and/or the force generator apparatus being splined to the drillstring outer casing. This might be with or without axial movement.

During typical RC drilling, there is the first part of drilling where the drill bit goes through soft mud/overburden. When using the hybrid drill bit in RC drilling, the concentric drill bit 12 can rotate and scrape the soft overburden. As RC drilling progresses the drill bit encounters "competent" rock. This is solid rock without fractures. At this point weight on bit can be transferred to the concentric drill bit causing the bit inserts to break the rock into chips. This rock is drilled by the annular drill bit 11, which can create a plug which is then broken up by the concentric drill bit 12 for return in the drilling fluid uphole 49/18. This is explained further below.

In use, when using the third variation, of the drill bit 10", drilling fluid 49 from the RC drilling apparatus 40 passes down through the apparatus, and down through channels 173/177 and exits through openings 172/175. Fluid exiting through internal openings 172 in the internal recesses 170 remains within the inner portion 160 of the drill bit 10" and returns through the return holes 18 and the concentric drill bit 12 carrying the chip samples to transport them back top hole for analysis. The retention of the drilling fluid predominantly within the interior region 160 of the drill bit 10" means that even if there is fractures in the formation, there is sufficient volume, flow and pressure of drilling fluid to return cuttings back up hole. In addition, a small amount of drilling fluid passes through the openings 175 to lubricate the outer perimeter 158" of the drill bit 10".

The cuttings return through holes 18 only if the annular drill bit 11 is being used in the R.C. configuration of Figure 3A, 3B, 3C.

Figure 3A, 3B, 3C is just one example of a reverse circulation drilling apparatus that the drill bit could be used with. It will be appreciated that the hybrid drill bit could be used in any reverse circulation drilling operation with any suitable reverse circulation drilling apparatus that can provide rotation to the annular drill bit and repeatable force to the concentric coring bit to repeatedly move the concentric coring bit.